The present application generally relates to methods and systems for measuring the amount of petroleum, gas, and water produced from a hydrocarbon well.
The following paragraphs contain some discussion, which is illuminated by the innovations disclosed in this application, and any discussion of actual or proposed or possible approaches in these paragraphs does not imply that those approaches are prior art.
Background: Production of Crude Petroleum Oil
Crude petroleum oil and gaseous hydrocarbons are produced by extracting them from subterranean reservoirs. Sometimes the oil and gas flows to the surface due to the natural pressure when a well is first drilled. Often, however, other methods are required to bring them, and particularly the oil, to the surface. These include a variety of pumping, injection, and lifting techniques used at various locations, such as at the surface wellhead (e.g. use of rocking beam suction pumping), at the bottom down-hole of the well (e.g. use of submersed pumping), all along with well casing string (e.g. use of gas injection lifting), and in the subterranean oil formation reservoir surrounding the well (e.g. water, combustion, or steam-driving the reservoir or formation). Each of these techniques results in crude petroleum oil and gas emerging from the well head as a multiphase fluid of varying proportions of oil, water, and gas. For example, a gas lift well has large volumes of gas associated with the well, with gas-to-oil volumetric ratios as high as 200 standard cubic feet of gas per barrel of oil, or higher. As another example, a water-drive reservoir can produce oil as an oil and water mixture, with water content percentages as high as 99%. In the petroleum industry, the water fraction in oil is known as the water cut (“WC”) and the oil fraction is referred to as the oil cut (“OC”).
Hydrocarbon well optimization methods include adjusting the well operating parameters and employing reservoir stimulation techniques. Decisions in the use of such optimization methods are greatly enhanced if accurate compositional data of the oil is available, both instantaneously and over time. Specifically, in one context of hydrocarbon well production optimization, it is important to be able to determine the amount of water mixed with the crude oil, which is often present as naturally-produced ground water, water from steam injection, and/or well injection water which has become eventually mixed with the oil as a result of a reservoir stimulation process. One such stimulation process is known as Steam Assisted Gravity Drain stimulation (“SAGD”). Another is the “Huff and Puff” stimulation method where steam is intermittently injected into the reservoir. Different types of stimulation processes can have different phase states upon start-up of the well.
As a further complexity to the multiphase characteristics of crude petroleum oil, a given well with a given production technique does not produce a constant multiphase composition and flow rate. First, wells deplete hydrocarbon-bearing reservoirs and/or formations, and there is generally, a decreasing output of hydrocarbon over days, weeks, months, or years of time. On the other hand, well composition and volumetric output can change in a matter of seconds. For example, upon start-up, a well can take several minutes or several hours to reach steady-state operation. Pressure, temperature, composition, and flow rate swings can occur during start-up. Second, some wells are in a constant state of composition and flow rate change. For example, one production technique uses intermittent gas injection lifting. Gas is periodically injected into the well purposefully, resulting in a periodic cycle to the well output, as in a waveform.
One constant requirement for all hydrocarbon well operations, regardless of production technique, is the need to determine how much oil and gas a given well is producing over a given period, e.g. the well production rate. To that end, well testing is routinely conducted on a given well to establish the composition and flow rate.
The variable production techniques and the resulting varying multiphase fluids present significant challenges to well testing systems and methods. For the most part, determination of the total volume of gas and volume of liquid produced over a given time is relatively easily established using gas-liquid separation techniques, and gas and liquid flow metering techniques known to a person having ordinary skill in the art of quantifying hydrocarbon well output production. However, a significant challenge lies in determining how much water is mixed with the petroleum oil in the total liquid output. Further, water cut can vary significantly, depending on a number of factors, including natural sources of underground water, well startup conditions, well upsets, and the production technique.
The need for accurately characterizing a particular well's performance is important to well operation and production output optimization. Optimization operations include reducing equipment failure and improving decisions to work-over the well. Reasons causing variable multiphase flows include drill string behavior, various bottom whole configurations to access more than one hydrocarbon formation at a time, and possible differing layers of oil and gas in a given hydrocarbon formation. Issues in interpreting the well characterization data include differing patterns of well behavior, various cyclic well behaviors, and varying durations of peak and minimum flows.
Background: Water Cut Analyses in Oil Production
When water is pumped to the surface of the Earth along with the crude petroleum oil, producers often attempt to physically separate the water from the oil, because the water can corrode pipes and damage down-stream processing equipment. Producers attempt to optimize the oil and gas production but minimize the water production. Further, the water has no value relative to the oil and in-fact can become a disposal or environmental problem wherever it is finally removed. Water-oil “separators” or liquid-liquid decanters are thus often used, before the crude petroleum oil is further transported from a well site or tank farm. However, the efficiency of such separators in achieving two pure streams of oil and water is often not 100%, and free water is still frequently entrained in the crude petroleum oil as it enters storage, in the range of about 0.10% to about 5%.
The need for a very accurate determination of water content and validation of the amount of water in crude petroleum oil is particularly important during the taxation of crude petroleum oil and the sale of crude petroleum oil, where the owner or seller of the oil does not want to pay taxes on water and the customer does not want to pay the price of oil for water. To that end, multiple determinations and cross-checks are often conducted on-line and off-line during petroleum production.
The offline method involves physically sampling the stream and analyzing it in a laboratory setting. In the petroleum industry, the sampling is usually done using a composite sampler which automatically opens a sample valve attached to a pipeline at some frequency to collect an aggregate sample into a sample container. The objective is to collect a sample which is representative of the production period of petroleum under consideration. After collection, the composite sample is usually picked up by a person and taken to a laboratory. The composite sample is then “sampled” to prepare aliquots, or sub-divisions of the composite sample, for each of the various characterizations, or analysis methods, to be used.
Three off-line analytical methods are commonly used for determining the water content of crude petroleum oil. These are the centrifuge method, the distillation method, and the titration method. See the American Petroleum Institute (“API”) Manual of Petroleum Measurement Standards, Chapter 10. The distillation and titration methods are relatively accurate, but are plagued by long analysis times and not suitable for use in the field or at the point of sale. The centrifuge method is quicker, but almost always under-reports the amount of water present. The American Society for Testing of Materials has reported the standard analytical errors for water content measurements using the three methods. The repeatability errors are 0.11% for the distillation method (see ASTM D4006), 0.15% for the titration method (see ASTM D4377), and 0.28% for the centrifuge method (see ASTM D4007). Note that the API does not have standardized methods for testing crude petroleum oil with water cuts above 2%.
Note that composite petroleum samplers and the associated analytical methods have other kinds of problems and disadvantages other than, for example, meeting a desired accuracy for a given determination. For example, results for composite samplers are typically only available at the end of a batch or a test, and there is no recourse if something goes wrong with the sampling system during the sampling process. At the end of the sampling and analysis, only a single number is available to consider. Additionally, the exposure of personnel to hazardous liquids associated with processing the samples is undesirable. Thus, the petroleum industry has continued to seek other methods that provide the required accuracy, speed, and safety.
One other standard on-line method is the use of two way or three way test separator vessels. This approach generally uses a tank sized to attempt to separate the well output into two or three streams, such as a gas stream, a water stream, and an oil stream, and then separately meter each stream. The Petroleum Engineering Handbook, 3rd Printing, from the Society of Petroleum Engineers, Richardson, Tex., Howard B. Bradley editor-in-chief, 1992, is hereby incorporated by reference. It describes such separators in Chapter 12. However, this approach has several drawbacks including susceptibility to not being able to separate emulsions of oil and water, large holdup volume, and large physical footprint.
Accordingly, the use of rapid on-line instruments such as densitometers, capacitance probes, radio frequency probes, and microwave analyzers to measure water content of petroleum products is becoming more common. In addition to providing increasingly accurate determinations of water content, real time water content results via on-line methods can provide beneficial operational advantages. Knowledge of when water becomes present in petroleum as it is being produced and the magnitude of the quantity of the water may provide an opportunity to divert the water before it reaches a transport pipeline, storage vessel, or shipping tanker. Additionally, the real time data may show if the water is detected in several short periods of time or if it is present across the entire production period. Furthermore, real time analyzer results can be compared to composite sampler results. Finally, on-line measurements of properties via unmanned instrumentation reduces the need human involvement in the process of measuring the composition of crude petroleum oil.
Background: Water Cut by the Density and Electromagnetic Characterization Methods
On-line densitometers can be used to ascertain the amount of water in petroleum oil. One on-line density method uses a Coriolis meter. This meter can be installed in the pipeline leaving the well or wells. Coriolis meters measure the density of a fluid or fluid mixture, and usually its mass flow rate as well, using the Coriolis effect. Then, calculations can be performed to indirectly determine the water percentage. For example, a Coriolis meter can measure the density of a water-oil mixture, ρmixture, and then perform a simple calculation method to determine the individual fractions or percentages of the water phase and oil phase. By knowing or assuming the density of the dry oil, ρdry oil, and the density of the water phase, ρwater phase, then a water weight percentage, ψwater, can be calculated as follows:ψwater phase=((ρmixture−ρdry oil)/(ρwater phase−ρdry oil))×100
Note that the above equation can work equally well using the specific gravities of the mixture, dry oil, and water phase, where specific gravity is the ratio of the particular density to the density of water at 4 degrees Celsius.
It should be recognized that the water percentage by density method is subject to uncertainty. First, due to natural variations of, for example, the hydrocarbon composition of crude petroleum oil, the density of the dry oil can vary significantly from the assumed or inputted value required for the simple calculation. Such a value inputted into a densitometer based on a guess or on history of a given oil well. Crude petroleum oils can range from about 800 kilograms per cubic meter (kg/m3) to about 960 kg/m3. Further, the water encountered in oil well production is most often saline. This salinity is subject to variability, ranging from about 0.1% by weight salt to about 28%. This results in a variation in the density of the water phase from about 1020 kg/m3 to about 1200 kg/m3. Again, this value would be inputted into a densitometer based on a guess or on the history of a given well.
Note also that an entrained gas phase, as is sometimes present, can dramatically affect the density of a crude petroleum oil liquid stream as measured by a Coriolis meter, if a precise correction method is not applied for the presence of the gas.
Another technique to determine the water percentage is to use a microwave analyzer, instead of a densitometer, to perform the in-line monitoring of the oil and water mixture.
U.S. Pat. No. 4,862,060 to Scott (the '060 patent), entitled Microwave Apparatus for Measuring Fluid Mixtures and which is hereby incorporated by reference, discloses microwave apparatuses and methods which are most suitable for monitoring water percentages when the water is dispersed in a continuous oil phase.
Note that the change in fluid mixture dielectric properties for a water and oil mixture can be affected by a number of parameters, including not only the percentage of water in oil, but also the individual dielectric constants of the oil phase and the water phase. For example, the dielectric constant of the dry crude petroleum oil itself can vary depending on its density and chemical composition. Note that temperature can affect the density of the oil and the water and thus the dielectric properties of each component and the mixture. However, temperature variations can easily be compensated for by using a temperature probe in-contact with the multiphase fluid being characterized to allow referencing to data sets or curves fit to the data sets for different temperatures.
Thus, both the densitometer method (“water cut by density”) and the electromagnetic characterization method (“water cut by electromagnetic characterization”) are subject to uncertainties. One approach to dealing with the uncertainty is to simultaneously use both methods to characterize a crude petroleum oil stream for water content. This joint use is practiced commercially. An example is the Compact Cyclone Multiphase Meter manufactured by Phase Dynamics, Inc. of Richardson, Tex.
When conducting joint densitometry and electromagnetic characterizations of a flow stream of mixtures of water and crude or partially refined petroleum oils, exact values of the electrical and physical properties of the pure water and oil phases are not always known. However, in certain situations, each method can supply estimates of the requires values to assist each other in determining water content in petroleum products.
An example of a such a supply of a physical property estimate is disclosed in U.S. patent application Ser. No. 11/273,613 to Bentley N. Scott entitled Methods for Correcting On-Line Analyzer Measurements of Water Content in Petroleum, and is hereby incorporated by reference, and hereinafter referred to as Scott '3613. Scott '3613 discloses that because a microwave analyzer is usually shop-calibrated across a range of water contents using a dry oil of a known density, the analyzer will report an erroneous water percentage if the dry oil being measured in the field shifts to a different density than that of the original dry calibration oil. The auto-correction method disclosed in Scott '3613 ameliorates this problem. Scott '3613 teaches that there is 0.03% WC by electromagnetic characterization error introduced for every 1 kg/m3 shift in actual dry oil density from the dry oil calibration density. It discloses that for water cut's less than about 5%, the density of the actual dry oil can be adequately estimated for use in calculations by the microwave analyzer by assuming the actual dry oil density is equal to the density of the mixture as measured by the densitometer. This assumption results in a maximum error rate of about 0.23% at about 5% water cut. This error rate compares favorably to the off-line analytical method error rates previously detailed. For well testing the error is more difficult to define and must be done by statistical methods of pulling a population of samples large enough to find a statistical mean and standard deviation. This method is not well defined and the true error is not known since each sample is an independent one and is subject to many errors with equipment and personnel. Since the lab method does not have a known standard error the resulting data is a measure of the reproducibility of the on line analytical equipment and the laboratory methods and handling of the samples.
Background: Crude Petroleum Oil Phase Behavior and Electromagnetic Characterizations
Still further uncertainty in conducting characterizations of crude petroleum oil can be caused by the physical chemistry of the oil, the water, and the mixture itself. For example, in the case of liquid-liquid mixtures undergoing mechanical energy input, the mixture usually contains a dispersed phase and a continuous phase. For water and oil, the mixture exists as either a water-in-oil or an oil-in-water dispersion. When such a dispersion changes from water phase continuous to oil phase continuous, or vice-versa, it is said to “invert the emulsion phase”. This is a rheological phenomena.
Dispersion of one phase into another occurs under mechanical energy input such as agitation, shaking, shearing, or mixing. When the mechanical energy is reduced or eliminated, coalescing of the dispersed phase can occur, where droplets aggregate into larger and larger volumes. Further, in a substantially static situation (e.g. reduced energy input), heavy phase “settling-out” or stratification can occur under the force of gravity.
A further complicating phase-state phenomena of liquid-liquid mixtures is that stable or semi-stable suspensions of dispersed-phase droplets can sometimes occur. This is usually referred to as an emulsion, which can be either stable or semi-stable. Certain substances are known as emulsifiers and can increase the stability of an emulsion, meaning that it takes a longer time for the emulsion to separate into two phases under the force of gravity or using other means. In the case of petroleum oils, emulsifiers are naturally present in the crude petroleum oil. For example, very stable emulsions can occur during petroleum processing, as either mixtures of water-in-oil or oil-in-water.
Another complicating phenomena is that the formation of dispersions and emulsions are sometimes “path-dependent.” Generally, path-dependence exists when the result of a process depends on its past history, i.e. on the entire sequence of operations that preceded a particular point in time, and not just on the current instantaneous conditions. In the case of emulsions, the process of forming the emulsion can be path dependent because the sequence of phase addition, mixing, and energy inputs can affect which phase becomes the dispersed phase and how stable the resulting emulsion is. Thus, if one does not know the history of the multiphase fluid undergoing dispersion or emulsification, one will not always be able to predict the “state” of the dispersion or emulsion, i.e. which phase is continuous and which is dispersed, even if the proportions of the phases are accurately known at a particular point in time.
For microwave analyzers, whether a dispersion or emulsion is water-continuous or oil-continuous has a significant effect on the analyzer's measurements. In the case of water-continuous dispersions or emulsions, the conductivity path established by the water continuous phase causes a significant change in the measured permittivity relative to the same proportion of phases existing as an oil continuous dispersion or emulsion. Additionally, further variations in the conductivity of the aqueous or water continuous phase caused, for example, by even relatively small changes in salinity, can significantly affect the measured permittivity results. Note that when the non-aqueous or oil phase is continuous, no conductivity path is established (because the droplets are not “connected” to form a continuous conducting circuit) and hence there is no significant effect on the measurements of a microwave analyzer due to the conductivity of the aqueous phase. Note also that this is only true when the wavelength of the electromagnetic energy is large compared to the emulsion size. When the emulsion size is larger than one eighth of a wavelength the voltage difference across the emulsion can be significant and therefore a correction must be made with respect to the salinity (conductivity at the frequency of measurement) of the water.
As a particular example of the complex behavior of oil-water mixtures and the impact of that behavior on electrical characterizations such as permittivity, consider FIG. 1A. It is a generalized phase diagram 100 of a particular crude petroleum oil and a range of aqueous solutions of varying salinity where the fraction of the water phase, Xw, is plotted against the frequency, f, as instantaneously read by a microwave analyzer. Note that although the lines are shown as straight lines the relationship between Xw and f may not be strictly linear. To illustrate aspects of the complex behavior of liquid-liquid mixtures, consider starting with a pure oil phase that is under-going a given amount of mechanical energy input, as is encountered when such a fluid is pumped through a restricting valve and is experiencing a pressure drop. This starting composition, on the path independent, oil-continuous line 101, is represented by point 102. Then, an aqueous saline solution could be added to the oil phase to form a mixture of water-in-oil, represented by points on line 101. The relationship between the permittivity frequency and the aqueous phase fraction is determined by the line 101. On this line, the multiphase fluid exists as an oil continuous phase with drops of dispersed aqueous phase. Then, increasing amounts of saline solution can continue to be added, up along line 101 to point 104. At point 104, the dispersion progresses along path dependent line 105 to point 106. At point 106, the dispersion inverts to an aqueous phase continuous dispersion, with an accompanying discontinuity in measured permittivity, jumping to a particular permittivity curve depending to a large extent on the salinity of the aqueous phase. Aqueous phase can continue to be added along salinity iso-lines in zone 107 to path-independency transition level 108. At path-independency transition level 108, path dependency is no longer present as the dispersion moves into zone 109. The fraction of aqueous phase can be increased to 1.00, with the permittivity being dependent on both the salinity and the fraction of the aqueous phase.
It should be noted that in certain emulsions, zone 107 may not exist at all, and line 105 might transition directly to zone 109.
In an another example of possible path dependency, the mixture may begin as a point located some where in a high water cut, path independent, salinity-controlling, aqueous continuous zone 109. Then, the aqueous fraction could be reduced to path-dependency transition level 110, and further reduced to aqueous fraction 112, along the iso-salinity lines within the high water cut, path dependent, aqueous-continuous zone 111. The iso-salinity lines within zone 111 are shown as dashed lines because they represent salinity levels which may be the same as that in zone 107. Additionally, path-dependency transition level 110 may or may not be equal to path-independency transition level 108.
Next, following the iso-salinity lines through zone 107, the dispersion would invert at aqueous fraction 112, and as aqueous fraction is further reduced, the relationship follows oil-continuous, path-dependent line 113 to point 104.
It should be noted that in certain emulsions or dispersions, zone 111 may not exist at all, and line 113 might transition directly from zone 109.
Thus, for the particular crude petroleum oil example above as it is mixed in various proportions with a variable salinity aqueous phase, at least three zones of compositional uncertainty can exist for the permittivity of aqueous continuous dispersions, of which at least two such zones are path-dependent. Additionally, at least three discrete curves can further relate the permittivity of oil-continuous mixtures, of which at least two such curves are path dependent.
Such complex physical chemistry leads to numerous uncertainties with regards to electromagnetic-energy-based composition determinations. For example, referring again to FIG. 1A of this application, frequency 114 can in-fact represent two different mixture compositions, 116 and 118, depending on how such compositions were formed, as previously described. Additionally, a particular aqueous fraction 119 can correspond to either an aqueous phase dispersion of varying salinity contents, points 120, each having a corresponding permittivity frequency (not shown) or an oil-continuous phase dispersion of a particular frequency 122.
It has been found that these compositional and permittivity frequency uncertainties can be reduced by using a number of methods, depending somewhat on which zone or curve the mixture state resides in or on. For example, to address the problems of phase inversion uncertainties in aqueous and non-aqueous multiphase mixtures, U.S. Pat. No. 4,996,490 to Scott (the '490 patent), entitled Microwave Apparatus and Method for Measuring Fluid Mixtures and which is hereby incorporated by reference, discloses microwave apparatuses and methods for accommodating phase inversion events. For the example of oil and water mixtures, the '490 patent discloses that whether a particular mixture exists as an oil-in-water or a water-in-oil dispersion can be determined by differences in the reflected microwave power curves in the two different states of the same mixture. Therefore, the '490 patent disclose microwave apparatuses and methods, including the ability to measure microwave radiation power loss and reflection to detect the state of the dispersion. In further embodiments of that invention, methods are disclosed to compare the measured reflections and losses to reference reflections and losses to determine the state of the mixture as either water-in-oil or oil-in-water, which then allows the proper selection and comparison of reference values relating the measured microwave oscillator frequency to the percentage water. An embodiment of the '490 patent is reproduced from that patent in FIG. 1B, which explained and described in detail later in this Application.
Thus, referring again to FIG. 1A of this application, for water fraction 119, the apparatus and the method of the '490 patent would be able to identify whether the dispersion is in zone 111 or on line 105. When the composition is on line 105, microwave analyzers using the method of the '490 patent are able to accurately determine the aqueous phase fraction.
Thus, solving the problem of accurately ascertaining the composition of crude petroleum presents challenges and requires solutions not adequately met by current approaches. More particularly, there is an increasing need for reduction of uncertainty in the characterization of crude oil as the value of petroleum continues to rise. More specifically, as the use and development of different production enhancement techniques continues to increase, the dynamics of compositional fluctuations at the wellhead adds further challenges to accurately determining crude petroleum oil production output.
Hydrocarbon Well Test Systems and Methods
The present application discloses systems and methods for characterizing a multiphase flow stream produced from a hydrocarbon well. As live characterization data is collected from a well discharge flow stream, a time series of measurements results. The systems and methods of the present application can filter the time series of data and then can assess the filtered time series for acceptable data quality. If the quality is acceptable, at least one characterization measurement can be outputted and filtering parameters can be selectively adjusted. If the quality is not acceptable, more data can be collected and the method can eb repeated until acceptable quality is achieved.
In some embodiments (but not necessarily all), the disclosed innovations can be used at the wellhead of (or slightly downstream from) a producing hydrocarbon well, to estimate the oil, water, and gas output.
In some embodiments (but not necessarily all), the disclosed innovations can be used at the wellhead of (or slightly downstream from) a producing hydrocarbon well and can use time series of measurements which include an electromagnetic characterization property, such as microwave permittivity, and a physical property, such as fluid density.
In some embodiments (but not necessarily all), the disclosed innovations can be used at the wellhead of (or slightly downstream from) a producing hydrocarbon well to improve the characterization of that well upon re-testing or start-up of that well.
The disclosed innovations, in various embodiments, provide one or more of at least the following advantages:                Some of the disclosed innovations can provide methods and systems to improve the characterization of hydrocarbon well production output using a single characterization system with improved accuracy across a wide variety of operating conditions.        Some of the disclosed innovations can provide methods and systems to reduce uncertainty caused by non-steady state gas or liquid phase behavior for a particular hydrocarbon well.        Some of the disclosed innovations can provide methods and systems to reduce the uncertainty caused by changing physical and electromagnetic properties of the aqueous, oil, and gas phases discharging from a particular hydrocarbon well and/or reservoir.        Some of the disclosed innovations can provide methods and systems to reduce the uncertainty caused by faults and/or spurious results and/or errors in the operation of a multiphase electromagnetic characterization system.        Some of the disclosed innovations can provide more accurate physical and/or electromagnetic property measurements.        Some of the disclosed innovations can provide near-real-time reduction of uncertainty to improve near-real-time manned or unmanned well-operations decision-making, such as whether to review a particular well's performance.        Some of the disclosed innovations can provide near-real-time reduction of uncertainty to improve the accounting of oil, water, and gas production from a particular hydrocarbon well.        